Good morning, and thank you for standing by. Welcome to the Enterprise first quarter conference call. I would now like to turn the call over to Randy Burkhalter. Please go ahead, sir.
Thank you, Christy. Good morning, everyone, and welcome to the Enterprise Products conference call to discuss first quarter 2019 earnings. Our speakers today will be Jim Teague, Chief Executive Officer, and Randy Fowler, President and Chief Financial Officer of Enterprise's General Partner. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, based on the beliefs of the company, as well as assumptions made by information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.
Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during the call. With that, I'll turn the call over to Jim.
Thank you, Randy. First, let me express my regrets for missing our analyst day. I would have much rather been with you guys, but three broken ribs and unbearable pain kept me away. I was glad, however, that you really got to see the quality of our people, have an appreciation for our culture, and hopefully get the message of the promising outlook for our business. Not long ago, there was a research note out titled "What Will Drive Investors Back into Energy Stocks." The report said the answer is show me the cash. In the first quarter, Enterprise did its part to show me the cash. Consistency and execution is critical in all facets of our business.
We demonstrated it in the first quarter by completing the conversion of one of our Seminole NGL pipelines into crude service, and with initial operations on the Shin Oak pipeline 4 months ahead of schedule. Successful execution also includes our ability to deliver returns on invested capital. We have consistently returned capital to our investors for 20 consecutive years of distribution growth and counting while maintaining healthy coverage. We call that show me the cash. We also take very seriously that many of our long-term investors rely on this income. Our balanced approach of returning capital, maintaining coverage while conservatively using leverage, has provided us the financial flexibility to not only weather the cycles, but continue to grow our business during those cycles. That balanced approach has us well-positioned to capitalize on organic growth opportunities without relying on the equity capital markets.
We believe this will lead to future growth in DCF per unit distributions and the value of our equity. We had an exceptional first quarter with three of our four business segments reporting higher gross operating margin. We set five operational records and six financial records. That's on the heels of a strong 2018. Excluding non-cash mark-to-market earnings, gross operating margin, adjusted EBITDA, and DCF each increased by approximately 18% in the first quarter compared to the first quarter of last year. DCF, excluding non-recurring items, was a record $1.6 billion, giving us a healthy 1.7 times distribution coverage for the quarter. We retained $665 million in the first quarter that is available to reinvest in our growth.
This record performance was driven by contribution from assets that began operations during the past year, volume growth on existing assets, our marketing group's ability to capture some of the west to east spread opportunities in crude oil and natural gas, which more than offset the effect of weaker gas processing margins, and temporary closure of the Houston ship channel due to the fire at the ITC terminal. As to capital projects on the supply side, our focus on the Permian continues. We placed the initial phase of our Shin Oak NGL pipeline in service at the end of February. It is currently running at 250,000 barrels a day. As I said, we completed the conversion of one of our Seminole pipelines from NGL to crude service. We refer to that as Midland to ECHO II. It is flowing greater than 200,000 barrels a day.
Note that given its location and interconnects, we will always have flexibility to convert this pipeline back to NGL service, depending on the pipeline supply-demand balances for crude oil and NGLs in the future. I doubt that anyone else will be able to offer this type of future flexibility to Permian producers and to markets. On the demand side, we expect to complete our LPG dock expansion in the third quarter, our iBDH plant at the end of the year, and partially initiate service of the ethylene export terminal also in the fourth quarter. We recently completed the restart of 55,000 barrels a day of fractionation capacity at our Shoup and Tebone facilities in South Texas and Louisiana, respectively. We expect fractionation capacity to be tight again in the second half of 2019. Anticipating further NGL supply growth, we're currently constructing two new fractionators in Mont Belvieu.
We're also developing PDH 2, and we feel confident that this project will be successfully commercialized. On the natural gas, natural gas liquids side, we expect to complete the third processing train at Orla this quarter and Mentone 1 in the first quarter of next year. Orla 1 and 2 were placed in service last year and are running full. When all of these facilities are completed, we'll have about 1.6 Bcf a day of natural gas processing capacity and 240,000 barrels a day of liquids production out of the Permian. We're in discussions with customers that could lead to our underwriting two more processing trains at Mentone. We also expect to complete the expansions of Front Range and Texas Express NGL pipelines in the third quarter. Many of you have seen that we filed permits to construct another crude pipeline out of Midland.
If successful, this would be our Midland to ECHO 3 pipeline. We're quite creative in naming these pipelines. We're receiving serious interest from customers who value Enterprise's ability to provide flow and quality assurance and market choices on our integrated system. This integrated system joins together our pipeline storage, Houston distribution system, and marine terminals, safeguarding quality for both producers and end users by way of uninterrupted delivery from the wellhead to refineries or docks. If we're able to successfully underwrite this third pipeline, we would have a lot of flexibility to convert Midland to ECHO 2 back into NGL service should demand support it. While on the subject of flow assurance, I want to share with you how we performed during the ITC fire and fog days that temporarily limited the traffic on the Houston ship channel.
None of our upstream customers saw any disruptions while ship channel traffic was impaired. In fact, some of our facilities were used by the authorities during the event. This is the value that a large integrated company like Enterprise provides. This is also the value of being in the Houston market, where we have access to four and a half million barrels a day of refining and 300 million barrels of storage. With our loading capabilities, we made up a significant portion of our vessel backlog in April and expect to load all of the remaining vessels in early May. During our Analyst Day, our fundamentals team covered the subject of light oil, how much growth do we see from the Permian, and where we see the demand. I think they did a good job explaining that light oil will find a home in petrochemicals and gasoline demand.
After that, we received a lot of questions about LPG demand. Can the world absorb all the future LPG supply? I know a lot of you have to think about these things, and you have to ask these questions, and Tony and his group do a lot of analysis on these subjects. If you want a deeper dive, I'm sure he'd be happy to do it during the Q&A. Let me give you my personal perspective. I don't worry about this for one second. The reason? I have a fundamental belief. Price creates demand, just as price creates supply. You can ask Tony about demand growth for propane in India. Despite record LPG exports from the U.S., propane is currently worth 40% of WTI and normal butane at 48%. These are historically low relationships that were not typical during the old days.
I think that's a reference to me. Back in the day, propane always sold at 70%-75% of crude. At 40% of crude, price will create demand. Before I turn the call over to Randy, let me say again how proud we are of our performance this quarter and how much we're looking forward to the opportunities we see in 2019. None of this is possible without the extraordinary efforts and teamwork of our employees. I could go on for an hour about the quality of the people we have here at Enterprise. Our strong results this quarter, after the record-setting year we had last year, is a tribute to their work ethic, their creativity, and the teamwork you see within our company. With that, I'll turn it over to Randy.
Thank you, Jim. Good morning, everyone. Starting off with the income statement. For the quarter, net income attributable to limited partners for the first quarter of 2019 was $1.3 billion, or $0.57 per unit on a fully diluted basis. This included $96 million, or $0.04 per unit, in non-cash mark-to-market gains. This represents an 11% increase in earnings per unit after adjusting for the effects of mark-to-market amounts versus the comparable adjusted EPU in the first quarter of 2018. As Jim mentioned, we did report six financial records for the first quarter, including record adjusted EBITDA of $2 billion and DCF excluding non-recurring items of $1.6 billion. If we follow the recent sell side theme of converting adjusted EBITDA into distributable cash flow. For the first quarter, we made this conversion of EBITDA to DCF at 82% for the quarter.
This illustrates the benefits of having lower leverage, lower interest rates, and a simple structure, which is very efficient in converting cash flow all the way down to the unit holder level. Cash flow from operations was $1.2 billion for both the first quarter of 2019 and 2018. Of note, cash flow from operations for the first quarter was reduced by $560 million for working capital purposes. This is compared to a use of $203 million for working capital purposes in the first quarter of last year. In traditional terms, our payout ratio, cash distributions paid to limited partners as a percentage of cash flow from operations, was approximately 80% for the first quarter 2019. If we take a look at the trailing 12 months, which if you would, sort of smooths out the noise of working capital seasonality, the payout ratio was 62%.
Free cash flow was $1.9 billion for the trailing 12 months ended March 31, 2019, which increased 89% compared to the trailing months ended March 31, 2018, and is $97 million less than the trailing 12 months for December 31, 2018. Again, some of that due to changes in working capital. We placed approximately $1.9 billion of major growth capital projects into service through April of this year, including the initial capacity on the Shin Oak NGL Pipeline and the conversion of Seminole into crude service. We have approximately $5 billion of major capital projects under construction that we expect to come into service between now and the end of 2020. Our capital investments in the first quarter were $1.2 billion, which includes $62 million of sustained CapEx.
We currently expect growth capital investment for 2019 to be in the range of $3.4 billion-$3.8 billion and another $350 million for sustaining CapEx. For 2019, we still expect to receive approximately $625 million of cash contributions from business partners in projects that are jointly owned. Moving to our balance sheet. At March 31, 2019, our total debt principal outstanding was $20. Assuming the first call date for our hybrids, the average life of our debt portfolio was 14.1 years. Assuming the final maturity date for the hybrids, the average life of the debt portfolio was 19 years, and the effective average cost of debt was about 4.5%. Adjusted EBITDA for the trailing 12 months, March 31, 2019, was $7.5 billion, and our consolidated leverage ratio was 3.4 times after adjusting for the partial equity treatment of the hybrid debt securities.
On consolidated liquidity, it was approximately $4.7 billion at quarter end, which included available borrowing capacity under our credit facilities and unrestricted cash. Moving on to equity issuances and purchases. Enterprise received approximately $43 million in net proceeds from the Distribution Reinvestment Program and the Employee Unit Purchase Program during the first quarter of 2019. The level of the participation in the DRIP program after turning off the discount was less than half of what it was in the prior quarter, which again, would have been with respect to the distribution paid out in November 2018. We anticipate it may come down further at the next reinvestment date. As we continue the transition to equity self-funding, we are now evaluating applying the reinvestment of distributions to open market purchases instead of new issuances.
During the first quarter of 2019, we repurchased 1.9 million units for $51.6 million, or approximately $27.83 per unit, which more than offset the 1.5 million units issued through the Dividend Reinvestment Plan and the Employee Unit Purchase Plan in February 2019. With that, Randy, I think we're ready to open it up for questions.
Okay. Thank you, Randy. Before we open the call up to Q&A, I'd like to mention that we have posted some slides on our website as supplemental information with respect to first quarter earnings. They're listed under the caption Presentations in the Investors section of our website. Christy, we're now ready to take questions from the audience.
Yes, sir. If you would like to ask a question, press star, then 1 on your telephone keypad. We ask that you limit yourself to one question and one follow-up question. We will pause for just a moment to compile the Q&A roster. We do have a question from Tristan Richardson of SunTrust.
Hey, good morning, guys.
Good morning.
We would have to say that the five beats in a row doesn't go unnoticed. The only thing is you're making our modeling skills not look so great. Just a quick question on your project execution and just pulling forward some of the projects, specifically Midland ECHO. Presumably, that allowed for some beneficial spread exposure. Fast-forwarding today, does that capacity start to shift to third-party use all at once, or is that a gradual shift over time?
You want to take it?
Yeah. Tristan, this is Brent Secrest. You look at Midland to ECHO I want to say contractually, Jay, for the first quarter, we were at 475?
Yeah, that's correct, Brent. 475.
We'll ramp up. Second quarter contracts come on, additional contracts come on, and I want to say we peak at 535. In the case of Midland ECHO 2, starting April 1st, the pipeline was handed over to the committed shipper, and that volume's at 205,000 barrels a day.
Helpful. Thanks. Then just similar question on the natural gas side. Do you see more commercial activity for a third party, or is some of that space that gives you that spread exposure stay throughout the year?
Hi, good morning, it's Brad Motal. I think it's going to stay there for the rest of the year and beyond. Frankly, I've been impressed with the amount of continued commercial opportunities we've had in the Permian. I felt like it was going to start to slow down a little bit, frankly, it hasn't. It's kept up its pace precisely.
Helpful. Thank you guys very much.
Our next question comes from Jean Ann Salisbury of Bernstein.
Good morning. The LPG export arb has really widened recently. Your export expansion should help with that. Can you share if it's mostly sold fixed fee or if you would have material exposure to the arb when that comes on?
This is Justin Kleiderer. From a spot perspective, you've certainly seen a widening of the arb, and that expansion is going to give us access to capitalizing on that wider arb. However, we maintain our focus on our long-term strategy of offering competitive rates on the term supply business. I think as we think long term, we're not going to deviate from that long-term strategy of ensuring that we capitalize on the long-term supply at competitive rates.
Okay, that makes sense. How do you see Shin Oak capacity ramping between now and the end of the third quarter?
This is Tug Hanley. Shin Oak's, as Jim mentioned, currently full at its initial capacity, 250,000 barrels a day. We'll be bringing on pumps between now and the end of the year, call it another 100,000 barrels a day by the end of the third quarter.
Okay. That's all for me. Thank you.
Our next question comes from TJ Schultz of RBC Capital Markets.
On the unit buybacks in the quarter, you noted it covered the DRIP and purchase plans. Anything to read into that as far as strategy on buybacks and maybe those changes if you go to open market purchases? Any more color on how you viewed this as opportunistic time on the buybacks?
Yeah. TJ , frankly, I don't think our perspective has changed that much since our analyst meeting three weeks ago. I think we're still looking to be opportunistic with the buyback program, as we highlighted at Analyst Day. We're looking at a number of projects in development that frankly, we're feeling pretty good about. We may need capital needs there. I think right now, we're just, like I said, being very deliberate and keeping our financial flexibility now. Really no change, just really more opportunistic in approach.
Okay. Then, you have a crude dock in Corpus through the Eagle Ford JV that's coming online. Would you expect any more storage around that as more pipes into Corpus are complete? Just if you can provide any color on the capacity to load across that dock. Thanks.
You can take that one. That dock is operational now, and we're working with our partner over there to bring that dock into operation. I want to say currently with the air permit, the capacity is just shy of 200,000 barrels a day, Jay? It's at 200,000 barrels a day. I think we're on record about this, but we do think there will be opportunities to help clear that market as pipelines come online, docks come on at different times, and there is some potential misalignment between pipelines and docks. Certainly, we're looking for opportunities like that.
Perfect. Thanks.
Our next question comes from Spiro Dounis of Credit Suisse.
Hey, good morning, everyone. First question, just on the Permian. Just curious if you're seeing any near-term impact on NGL volumes out of the Permian as a result of the Waha basis. Curious if that's also resulted in any sort of meaningful impact on liquids and processing economics.
This is Brad Motal again. We have not seen any impact from shutting gas relative to our processing volumes on our equity gas plants out in the Permian.
Okay, great. I believe you made the comment at the Analyst Day that I think you're finding it increasingly harder to offer NGL customers transportation without also offering frac and export capability. Curious if that's resulted in ability to maybe charge premium prices, just given that you're integrated and obviously differentiated on that front. Are you able to sort of see that same dynamic, either in crude or refined products as well?
Anybody? Hey, this is Brent. I think that the ability to offer all of those services is a benefit to Enterprise, and I don't think we're shy about saying that we leverage the integration to offer those type of servicesI think the customers that we have the most success with are probably typically a larger type customer who want to be in that game, they want to be in the export game. In the case of crude oil, I do think that us having control of that barrel all the way through, from the field all the way to the dock when it comes to maintaining quality and executing what that producer wants us to do with that barrel, I do think it gives us an advantage. I think, frankly, you're seeing it with how our volumes are coming on quarter by quarter.
Is it fair to say, Brent, on Midland-to-ECHO 1, I think you have only one contract that doesn't have an associated dock deal with it?
That's right.
I think that one contract is in negotiations with us for a dock deal.
That's correct.
That's evidence that, to your point, the bundle service is quite valuable to us.
Got it. Really appreciate that color. Thanks, guys.
Our next question comes from Justin Jenkins of Raymond James.
Hey, good morning, everybody. I guess maybe thinking about the propylene market, seemed like that was one of the few headwinds in 1Q. Maybe just your thoughts on how operations unfold here in 2Q and market outlook in the nearer term for that particular business line.
I'm going to let Chris D'Anna jump on that. I think it was headwinds because last year, first quarter, we had $0.20-plus spreads, refiner grade to polymer grade. That's not something that you would expect long term. I think our spreads were more in the range of what we would've expected. Chris?
No, that's absolutely right, Jim. Our first quarter of last year, the spreads were just historically very wide, and we've returned more to a normal. Our pricing here in the U.S. is much lower than other regions, that's also opened up the opportunity to export quite a bit of volume. We're exporting record volumes of propylene across our dock.
Perfect. Thanks for that. I guess maybe follow up here on the CapEx bump for 2019. Is that an acceleration of existing projects, or is that a combination of that and maybe some new projects to the fold?
Yes, in coming in and looking at it, the increase was approximately about $250 million. I'd say almost 60% of that is in projects that are $10 million and less. Frankly, that's normally where we get our best returns on capital are from those smaller projects.
Perfect. Thanks, guys.
Our next question comes from Theresa Chen of Barclays.
Good morning, everyone. In your prepared remarks, you guys talk about the propane price being lower as a percentage of crude than where it's historically been. How much of that is a function of price pressure at Mont Belvieu? Because it looks like we're at export capacity, and with the winter demand domestically for propane going away, more of it, I'm sure, needs to clear the market.
That's right.
Do you expect that we're going to see more pressure on propane and butane until your export expansion comes on?
I think you could see a little more pressure on both of them. You're right. It's at 40% of crude because winter's over and there's a lot of supply. I mean, you nailed it.
Okay. I guess, just as a follow-up on your LPG export expansion. If you are doing contracting, what are the rates and tenor looking like for those contracts versus what you historically assigned on your first round of export?
You want to take it?
Capacity.
This is Brent. It's changed in a sense. I think you're seeing the U.S. producers step in for these type of contracts. In the first kind of wave on these, it was traders, it was potentially end users who were trying to open up the U.S. market, so they had alternative sources of supply. I think now, to go back to your prior question, in the case of HD5 propane, it's got to find somewhere to go. It's going to get turned into export quality propane. I feel confident on terms of the length. Obviously, we're not going to get the rates that we got the last time around. Frankly, we've been fairly public that that was probably a mistake. We probably asked for too high of numbers, and we lost our market share.
You're going to see rates that are quite a bit less than we got the first time around. You'll see a different type of customer for us. In terms of term, I think we'll see longer term.
Let me say, when Brent says lost our market share, he's talking about going from 80% to 45% to 50%. With all the volume, I don't think we could continue being the only game in town. The other thing he's saying is, we're not going to make the mistake of having prices that invite more competition. People are going to have to compete hard to beat our pricing.
Fact of the matter is we have a brownfield project, and for us to expand it's much more economical than to allow greenfield projects to start up.
Okay. Very helpful. Then, can you remind us when the hedges that you have on your volumes for Midland to ECHO roll off? Should we think that you guys are going to continue to hedge on basin and any uncontracted capacity you have on Midland to ECHO I and II?
This is R. Daniel Boss. The hedges that we have on Midland to ECHO, they primarily roll off towards the end of 2019, then there's a small portion that goes into 2020. There's about $26 million of gains left on those hedges that will come off mostly in the second quarter and fourth quarter of this year. Beyond that, on the capacity that's
Not contracted under long-term agreements, that's pretty wide open.
Should we think that you guys are going to continue to hedge that out?
I think in terms of how we use that space, Brad talked about it, and you'll hear potentially Zach Strait talk about it, is we have opportunity with that space. Our plan and our methodology is to allow people who are willing to do long-term contracts with us to use that space. We'll try to convert that to long-term deals. If we're having a difficult time getting that done, then if we feel like the market is at a number that we like, then we could step in and hedge it. Right now, the focus is to get long-term deals.
It's the same thing on the capacity we have on natural gas from Waha to the Gulf Coast. We're taking advantage of it right now, we plan to leverage it into Mentone 3 and Mentone 4, right Brad?
Yeah.
Your next question comes from Keith Stanley of Wolfe Research.
Hi, good morning. Just some quick clarifications. On crude marketing being so strong in the first quarter, is it fair to say most of the year-over-year increase there is just Seminole ramping up before the contracts kicked in in April? Were there other areas of strength in crude marketing?
I think, if you look at Midland-to-ECHO 2, I want to say we averaged just shy of 100,000 barrels a day on that. That was unhedged space. That rode the value of what the market was at the time. There is some unhedged space we have on other pipelines. In terms of what you can expect quarter-over-quarter, you'll see obviously increased volumes on Seminole. The rate will probably go down, or it will go down, but at the end of the day, that's the highest rate we have on any crude transport out of the Permian Basin. The fact of the matter is, there will be other opportunities, and it's hard for me to sit there and say the opportunity's going to be at the dock or the opportunity's going to be in storage.
We talk about all the opportunities we have at this company across all the different commodities. In the case of maybe this quarter, there was an opportunity on crude basis.
Okay. That's helpful. On Frac 10, did Frac 10 get accelerated now, I just want to make sure I'm reading this right, to the fourth quarter of 2019 instead of early 2020?
Zach, you too nervous to answer a question?
It did get accelerated.
That's a nice short answer.
Thank you.
Your next question comes from Colton Bean of Tudor, Pickering, Holt.
Thanks. Just to follow up briefly on the crude oil basis discussion there. To some degree, was Q1 impacted at all by the Cushing to Houston spread? I guess, if so, when you guys expanded Seaway last year, was there incremental spot capacity associated with that, or was that all thought of as third party?
That Enterprise marketing has Seaway space. When the expansion came out last year, that space was fully contracted for. If you look at the Seaway pipeline, the fact that it achieves market-based rates, there can be an arb there, obviously that's shared with our partner. In the case of volumes, Enterprise from the marketing standpoint is moving crude oil down Seaway as it makes sense. Sometimes those volumes are less, and sometimes they're more.
Got it. I guess just to circle over to Shin Oak. Given last week's update on Alpine High, does that change your view on the ramp over the course of 2019? If so, is there any potential to backfill that with other counterparties?
Yeah, this is Tug. No, it doesn't. Just for example, the Shin Oak main line is in service right now flowing that 250,000 barrels a day, we have yet to complete the lateral down to get those volumes, which will be sometime around June. We don't see that impacting us. Furthermore, I believe some of the curtailments or reductions are dry gas, not rich gas. That's what we're seeing.
The other thing on Shin Oak is the most reliable supply to Shin Oak and to our fractionators comes out of our own processing plant. I don't think we're through. We've mentioned the possibility of two more Mentone plants. That's another 80,000 barrels a day, Tug. I don't think that's going to be the end of our processing plants in the Permian. All of which will feed Shin Oak.
Shin Oak, just a reminder, is not just connected to the Permian. It's connected to our entire system, which touches just about every basin there is.
Got it. Thank you.
Our next question is from Shneur Gershuni of UBS.
Hi, good morning, guys. First off, just wanted to say, really appreciate the increased disclosures that you guys disclosed with today's earnings. Just a couple of questions here. Kind of a follow-up on the buyback and the DRIP questions from earlier. Just what are your thoughts on just turning the DRIP completely off at this point right now? In your responses on buybacks, you talked about wanting to be opportunistic and at the same time you're evaluating a lot of large projects. If I recall correctly, at the analyst day, you talked about $5 billion to $10 billion worth of projects that you were hoping to FID at some point. Is there something more than that you're thinking about? I mean, the results, Jim, as you said, you showed us the cash.
You're producing very healthy excess distributable cash flow that can certainly fund that kind of a backlog. Is there something more that we should be thinking about, or could we actually see a more elevated pace of buybacks?
Yes, sure. On the DRIP, again, you have some participants in the DRIP that just like to reinvest without broker fees, frankly, and some of that cash is going to continue to come in. Rather than come in and just turn that program off altogether, we could come in and maintain our flexibility by continuing the program. Instead of the units being sourced from newly issued units, you just source the units by doing open market purchases. I think, one, it still provides the company some flexibility on a longer-term basis, but then also comes in and continues to those participants that want to continue to purchase through the DRIP, even without a discount. It still keeps that option of a low-cost investment option for them. As far as being opportunistic on the DRIP, really, like I said, not much changed from three weeks ago.
I think we still see $5 billion to $10 billion worth of projects under development. The guys are continuing to chase other projects as well. Right now, just looking to come in and maintain flexibility, and be opportunistic on the buyback. Really not a lot additional perspective I can give you.
Okay. Maybe as a follow-up question, obviously, you're talking about your LPG export capabilities and how strong it is. You have some peers, or should I say, competitors that are expanding theirs and others that are evaluating it, and so forth. Is there an opportunity for you. I'm not sure if the word opportunity is the right word, but just sort of given the competitive landscape, I mean, you kind of want to keep the export capacity to something that's obviously manageable for the market. Do you sort of sit there and say, "Let's take a lower price on our export fees for a period of time to ensure that all this proposed capacity and potential capacity doesn't actually end up getting built?" Just kind of wondering about your thoughts on the competitive dynamic there.
I think Brent said it, as did Justin, we're going to be very competitive on long-term deals. That translates to we're not going to make the mistake we made the last go-round. We're not looking at $0.12 fees. We're looking at fees that I doubt people can build greenfield on. Is that right, Justin?
That's right.
All right. I guess that answers the question. Perfect. Thank you very much, guys. Really appreciate the call.
Christy, this is Randy. We have time for one more before we cut the Q&A off, okay?
Yes, sir. Your final question comes from Michael Blum of Wells Fargo.
Thank you. Appreciate it. Good morning, everybody. Two related questions on Midland-to-ECHO 3. I guess the first question is, I think consensus view is that within one year, the Permian would be pretty overbuilt in terms of crude takeaway capacity. I just wanted to understand in the context of that, is that a bad assumption? What are you seeing that you think you're going to have demand for another incremental crude pipeline out of the Permian? The second part of that question is, a competitor pipe recently increased the cost pretty substantially of their crude pipe, and they pretty much talked about rising steel and labor costs. I wanted to kind of see what you guys thought in terms of if you're seeing any of that. Thank you.
Hello, Michael. It's Jim. I'll take the first part laterally to Brent, then we'll let Graham answer the last part. When you have a large producer that wants you to build a pipeline, you take a hard look at it. We differentiate. You see all the pipe coming out of the Permian. I agree, there's a lot of pipe. We differentiate what's going to Corpus, what's going to Cushing, as it relates to what's going to Houston. Houston is the big sponge, most of your major producers want to go to Houston, they want to go to the big sponge.
They like the fact that when they come through Enterprise, they're going to make sure their quality is going to be, we're going to keep their quality high, and we're going to give them 4.5 million barrels a day of market or refining market. We're going to give them 300 million barrels of storage. We're going to give them the ability to export their barrels. When we look at, oh God, there's a lot of pipelines, we say there's not enough to Houston, and I think that's what the major producers think.
I'll add to that, Jim. The fact of the matter is we have a decent number of producers who are coming to us asking us to build another pipeline. When I ask you to do that, then obviously you have to take a look at it. If you look at what we have upstream of our system in Midland and what we have downstream of our system in Houston, when you put everything together, it looks like a really good project. Now, if you want to take out all the production and Tony has his curve, and you want to apply the pipeline capacity on there, I would agree with you that it does look overbuilt. To Jim's point, what doesn't happen? I think barrels going to Cushing probably don't happen.
To apply 100% capacity factor to pipelines that go to Corpus, I think that's very optimistic. Then if you apply the pipelines that go to Corpus that have acreage dedications, I'm not sure that equals 100% capacity factor. Our contracts, if you look at our contracts, and they're essentially all 10-year contracts, won't expire until 2026, then we kind of look at that timeframe and find out what's overbuilt. At that point in time, it looks like the Permian's underbuilt when it comes to pipeline capacity. Jim alluded to his comments about converting crude oil back to an NGL line that was converted to a crude line back to an NGL line. That's an opportunity. That's an optimization that we have. Ultimately, we don't have any contracts expiring during this overbuilt time. If we did, I probably would be more concerned about it.
Graham, what about the cost?
As far as the cost, we're seeing slight increases in cost from the time we did Midland to ECHO 1. Nothing substantial, but I think we've been able to lock in cost for steel and pipe. Steel prices have actually gone down. Pipe has stayed relatively flat during that time period just due to the impact of the tariffs. All of that we can do is make a project work for Brent and his team.
Great. Thank you.
Okay, Christy, if you would you please give our listeners the replay information before we close the call? Thank you.
Yes, sir. Thank you all for participating in today's conference. This call will be available for replay beginning at 1:00 P.M. Eastern time today through 11:59 P.M. Eastern time on May the 9th, 2019. The conference ID number for the replay is 6667747. Again, that conference ID for the replay is 6667747. The number to dial for the replay is 1-800-585-8367 or 855-859-2056 or 404-537-3406.
Thank you. Thank you, Christy. Thank you everyone for joining us today, and have a good day. Goodbye now.
Thank you again for attending. You may now disconnect.